In common methods for producing oil from a well drilled into an oil-bearing subsurface formation, a string of steel production tubing is positioned in the wellbore and extends from the subsurface production zone up to a pump jack at surface in accordance with well-known methods. A downhole pump is disposed within the production tubing in the production zone to raise well fluids (e.g., oil, gas, formation water) to the surface, by reciprocating vertical movement of a travelling valve incorporated into the pump. The travelling valve is reciprocated by a typically steel “sucker rod” string extending upward within the production tubing to the well where it connects to a polished rod extending upward through a wellhead tee and stuffing box to connect to the “horse head” at the free end of the “walking beam” of the pump jack. By means of a suitable motor and associated mechanical linkage, the pump jack is operable to rock the walking beam such that the horse head reciprocates up and down, thereby alternately raising and lowering the sucker rod and the travelling valve, causing well fluids to be drawn into the well and the production tubing, and to be moved upward within the production tubing toward the wellhead, on each upward stroke of the travelling valve.
As the sucker rod reciprocates within the production tubing, it inevitably comes into contact with the inner wall of the tubing. The resultant friction between the steel sucker rod and the tubing causes wear on both the rod and the tubing. Such wear is a particular problem in “deviated” wells, in which the rod string will unavoidably rub against curved portions of tubing transitioning between vertical and horizontal (or slanted) sections of such wells. In addition to causing wear, the friction between the sucker rod and the tubing increases the magnitude of the force that needs to be provided by the pump jack to raise the sucker rod (and the travelling valve) on each upward stroke.
As an alternative to a pump jack as described above, well fluids may also be produced using a wellhead apparatus that rotates a sucker rod string to drive a downhole screw pump (also known as a positive displacement pump), rather than reciprocating the sucker rod string up and down. Although rotating sucker rods thus function in a different fashion than reciprocating sucker rods, they are nonetheless prone to friction-induced wear due to contact with the tubing.
Sucker rods are typically round or semi-elliptical in cross-section, and typically hot-rolled from carbon or alloy steel, with diameters ranging from ⅝ to 1-¼ inches. Sucker rod strings are commonly made up as a string of individual sucker rods (typically 25 feet in length) threaded together using internally-threaded tubular couplers. The ends of a threaded sucker rod are typically upset (i.e., larger in diameter than the main length of the rod), and are threaded for mating engagement with couplers. The upset portion at each end of a threaded sucker rod is typically about 5 inches long, and includes a tool-engagement section (e.g., wrench flats) to facilitate use of a wrench to tighten a coupler onto the rod. The threaded upset ends of a sucker rod are commonly referred to as pin ends.
It is also known to use a continuous (or so-called “endless”) sucker rod instead of a sucker rod string as described above. A continuous sucker rod has only two pin ends; i.e., a lower pin end for connection to the travelling valve of a downhole pump, and an upper pin end for connection to the polished rod. Continuous rod may be several thousand feet in length, depending on the depth to the production zone. It is known to mitigate the undesirable consequences of friction between sucker rods and production tubing by coating the sucker rods and/or lining the tubing with a low-friction material such as HDPE (high-density polyethylene). Such coatings also provide protection against corrosion in addition to protecting against friction-induced wear. Other polymeric coating materials that may be used for coating sucker rods can comprise polyethylene terephthalate (“PET”), polypropylene, polystyrene, epoxy, and acetyl, ethylene (“ETFE”), polytetrafluoroethylene (PTFE, or “Teflon”®), polyphenylensulfide (PPS, or “Fortron”®), polyamide (nylon), polyester, polyethersulfone, polyethylene include but are not limited to polyvinylidene fluoride (PVDF), ethylene tetrafluoroethylene (ETFE), polytetrafluoroethylene (“PTFE”, or “Teflon”®), polyphenylensulfide (“PPS”, or “Fortron”®), polyamide (nylon), polyester, polyethersulfone, polyethylene terephthalate (“PET”), polypropylene, polystyrene, epoxy and acetyl.
International Publication No. WO 2012/109736 (Moore et al.) teaches one process for coating continuous sucker rods with HDPE or other plastic or polymeric materials. Coated continuous rods have been found to have considerably longer service lives than uncoated rods in comparable operating conditions. For example, in approximately 250 producing wells in Alberta (Canada) refitted to date with continuous sucker rod coated in accordance with WO 2012/109736, rod service life (i.e., operational time before the rod replacement is required due to wear and/or corrosion) has been found to increase from an average of two months (for uncoated continuous rod) to as much as six months or more, thus greatly reducing downtime and associated costs. In addition, virtually no breaks due to wear and corrosion have occurred in the main portions of the continuous rods (i.e., away from the portions of the rod near the upset pin ends).
It is not uncommon for sucker rods to fracture due to fatigue after being in service in a producing well for a period of time. These fractures typically occur within one foot (305 mm) or so of upset pin ends of the rod. When a fracture occurs in one section of rod in a jointed sucker rod string, repair is commonly done by extracting the portion of the rod string above the fracture point, using an appropriate fishing tool to lift the section of the rod string below the fracture (along with the attached travelling valve of the downhole pump) as necessary to fully expose the lower portion of the broken rod section, uncoupling both portions of the broken rod section, and then coupling a replacement section into the rod string. The repaired rod string can then be lowered back into the tubing, and production from the well can resume.
In the case of wells using continuous sucker rods, it has been observed that rod fractures occur much more often near the lower pin end than near the upper pin end. When a continuous sucker rod fractures near its lower pin end, the length of rod above the fracture must be extracted from the well for repair, and the lower pin end (with attached travelling valve) must also be extracted from the tubing. To repair the rod, it is cut off at an undamaged point away from the fractured end, and a new pin end is welded to the rod. When the continuous rod is a coated rod, however, the coating needs to be repaired as well. It is highly desirable for the coating repair to restore the integrity of the coating as fully as reasonably possible, particularly in cases where the lower pin end is being replaced. Given that fractures in continuous rods occur most often near their lower pin ends, effective restoration of the integrity of the coating of a coated continuous rod after repair of a rod fracture is an important consideration to protect the replacement pin end and the repair weld zone against corrosion and wear, and thereby to maximize the service life of the repaired coated rod. To do this, however, first requires removing the old coating from the rod before repairing the rod and placing a new coating thereon.
It is, therefore, desirable to provide a rod coating stripper that provides an easy and safe way to remove the coating from the rod.